Nature of Operations and Summary of Significant Accounting Policies	3 Months Ended
Mar. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature of Operations and Summary of Significant Accounting Policies	NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Organization and Nature of Business GMX Resources Inc. and its subsidiaries (collectively, “GMX” the “Company”, “we,” “us” and “our”) is an independent oil and natural gas exploration and production company with a portfolio of leasehold acreage in multiple resource plays that allows the Company flexibility to deploy capital based on a variety of economic and technical factors, including commodity prices (including differentials applicable to the basin), well costs, service availability, and take-away capacity. Prior to 2011, the Company focused on the development of the hydrocarbon formations in East Texas including the Cotton Valley Sands (“CVS”) layer in the Schuler formation and the Upper, Middle and Haynesville/Lower Bossier layers of the Bossier formation (the “Haynesville/Bossier Shale”, or “H/B”), in the Sabine Uplift of the Carthage, North Field primarily located in Harrison and Panola counties of East Texas (previously designated as our “primary development area”). In late 2010, we made a strategic decision to expand our asset base and development activities into other basins in order to diversify our significant concentration in natural gas to a multiple basin and commodity strategy with more liquid hydrocarbon opportunities. In the first half of 2011, we acquired core positions in over 75,000 undeveloped net acres in two of the leading oil resource plays in the U.S.: the Williston Basin of North Dakota/Montana, targeting the Bakken/ Three Forks Formation; and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We believe the flexibility with the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage will enable us to generate higher cash flow growth to fund our capital expenditure program. The Company is leveraging our expertise in H/B Shale horizontal drilling to successfully develop these newly acquired oil resource plays. We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which sold its assets in 2011 and is not active, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our East Texas development area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. Kinder Morgan Endeavor LLC (“KME”) owns a 40% membership interest in Endeavor Gathering. Basis of Presentation The accompanying unaudited consolidated financial statements and condensed notes thereto of GMX have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in GMX’s 2011 Annual Report on Form 10-K (“2011 Form 10-K”). In the opinion of GMX’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the unaudited consolidated balance sheet of GMX as of March 31, 2012, and the results of its operations and cash flows for the three months ended March 31, 2012 and 2011. Earnings Per Share Basic earnings (loss) per common share is computed by dividing the net income (loss) applicable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. Because the Company was in a loss position for the three months ended March 31, 2012 and 2011, the instruments mentioned above would decrease diluted loss per share, which would result in antidilutive instruments. Therefore, there were no dilutive shares for the three months ended March 31, 2012 and 2011. Oil and Natural Gas Properties The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $3.7 million as of March 31, 2012 and $3.8 million as of December 31, 2011, respectively, that have not been placed in service but for which we plan to utilize in our on-going exploration and development activities. Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent interest rate. The cost of unproved properties is added to the future net revenues less income tax effects. Future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges. The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Natural gas represents 70% of the Company’s total production for the three months ended March 31, 2012, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first three months of 2012, the 12-month average of the first day of the month natural gas price decreased 9% from $4.12 per MMbtu at December 31, 2011 to $3.73 per MMbtu at March 31, 2012. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $28.9 million for the three months ended March 31, 2012. Assets held for sale are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. Subsequent increases in fair value less cost to sell will be recognized as a gain, but not in excess of the cumulative loss previously recognized. For the three months ended March 31, 2012 and 2011, we recognized an impairment loss of $0.1 million and $0.2 million, respectively, related to the assets held for sale. In April 2012, the Company sold a compressor included in assets held for sale as of March 31, 2012, for $1.5 million and no gain or loss was recognized on that sale. Recent Accounting Standards In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. The issuance of ASU 2011-5 is intended to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance in ASU 2011-5 supersedes the presentation options in ASC Topic 220 and facilitates convergence of U.S. generally accepted accounting principles and International Financial Reporting Standards by eliminating the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requiring that all non-owner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements. In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S GAAP and IFRS. This amendment of the FASB Accounting Standards Codification is to ensure that fair value has the same meaning in U.S. GAAP and IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of the guidance did not have any material effect on the Company’s financial statements.

NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Organization and Nature of Business

GMX Resources Inc. and its subsidiaries (collectively, “GMX” the “Company”, “we,” “us” and “our”) is an independent oil and natural gas exploration and production company with a portfolio of leasehold acreage in multiple resource plays that allows the Company flexibility to deploy capital based on a variety of economic and technical factors, including commodity prices (including differentials applicable to the basin), well costs, service availability, and take-away capacity.

Prior to 2011, the Company focused on the development of the hydrocarbon formations in East Texas including the Cotton Valley Sands (“CVS”) layer in the Schuler formation and the Upper, Middle and Haynesville/Lower Bossier layers of the Bossier formation (the “Haynesville/Bossier Shale”, or “H/B”), in the Sabine Uplift of the Carthage, North Field primarily located in Harrison and Panola counties of East Texas (previously designated as our “primary development area”).

In late 2010, we made a strategic decision to expand our asset base and development activities into other basins in order to diversify our significant concentration in natural gas to a multiple basin and commodity strategy with more liquid hydrocarbon opportunities. In the first half of 2011, we acquired core positions in over 75,000 undeveloped net acres in two of the leading oil resource plays in the U.S.: the Williston Basin of North Dakota/Montana, targeting the Bakken/ Three Forks Formation; and in the oil window of the Denver Julesburg Basin (the “DJ Basin”) of Wyoming, targeting the emerging Niobrara Formation. We believe the flexibility with the acquisition of the liquids-rich (estimated 90% oil) Bakken and Niobrara acreage will enable us to generate higher cash flow growth to fund our capital expenditure program. The Company is leveraging our expertise in H/B Shale horizontal drilling to successfully develop these newly acquired oil resource plays.

We have three subsidiaries: Diamond Blue Drilling Co. (“Diamond Blue”), which sold its assets in 2011 and is not active, Endeavor Pipeline Inc. (“Endeavor Pipeline”), which operates our water supply and salt water disposal systems in our East Texas development area, and Endeavor Gathering, LLC (“Endeavor Gathering”), which owns the natural gas gathering system and related equipment operated by Endeavor Pipeline. Kinder Morgan Endeavor LLC (“KME”) owns a 40% membership interest in Endeavor Gathering.

Basis of Presentation

The accompanying unaudited consolidated financial statements and condensed notes thereto of GMX have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, certain footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) have been omitted. The accompanying consolidated financial statements and notes thereto should be read in conjunction with the audited consolidated financial statements and notes thereto included in GMX’s 2011 Annual Report on Form 10-K (“2011 Form 10-K”).

In the opinion of GMX’s management, all adjustments (all of which are normal and recurring) have been made which are necessary to fairly state the unaudited consolidated balance sheet of GMX as of March 31, 2012, and the results of its operations and cash flows for the three months ended March 31, 2012 and 2011.

Earnings Per Share

Basic earnings (loss) per common share is computed by dividing the net income (loss) applicable to common stock by the weighted average number of shares of common stock outstanding during the period. Diluted earnings (loss) per common share is calculated in the same manner, but also considers the impact to net income (loss) and common shares for the potential dilution from our convertible notes, outstanding stock options and non-vested restricted stock awards. Because the Company was in a loss position for the three months ended March 31, 2012 and 2011, the instruments mentioned above would decrease diluted loss per share, which would result in antidilutive instruments. Therefore, there were no dilutive shares for the three months ended March 31, 2012 and 2011.

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for its oil and natural gas properties and activities. Accordingly, the Company capitalizes all costs incurred in connection with the acquisition, exploration and development of oil and natural gas properties. The Company capitalizes internal costs that can be directly identified with exploration and development activities, but does not include any costs related to production, general corporate overhead, or similar activities. Capitalized costs include geological and geophysical work, 3D seismic, delay rentals, drilling and completing and equipping oil and gas wells, including salaries and benefits and other internal costs directly attributable to these activities. Also included in oil and natural gas properties are tubular and other lease and well equipment of $3.7 million as of March 31, 2012 and $3.8 million as of December 31, 2011, respectively, that have not been placed in service but for which we plan to utilize in our on-going exploration and development activities.

Capitalized costs are subject to a “ceiling test,” which limits the net book value of oil and natural gas properties less related deferred income taxes to the estimated after-tax future net revenues discounted at a 10-percent interest rate. The cost of unproved properties is added to the future net revenues less income tax effects. Future net revenues are calculated using prices that represent the average of the first day of the month price for the 12-month period prior to the end of the period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives qualifying as cash flow hedges.

The primary factors impacting the full cost method ceiling test are expenditures added to the full cost pool, reserve levels, value of cash flow hedges and natural gas and oil prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is generally written off as an expense. Natural gas represents 70% of the Company’s total production for the three months ended March 31, 2012, and as a result, a decrease in natural gas prices can significantly impact the Company’s ceiling test. During the first three months of 2012, the 12-month average of the first day of the month natural gas price decreased 9% from $4.12 per MMbtu at December 31, 2011 to $3.73 per MMbtu at March 31, 2012. As a result of the Company’s quarterly ceiling test, the Company recorded impairment expense related to oil and gas properties of $28.9 million for the three months ended March 31, 2012.

Assets held for sale are carried on the balance sheet at their carrying value or fair value less cost to sell, whichever is less. Subsequent increases in fair value less cost to sell will be recognized as a gain, but not in excess of the cumulative loss previously recognized. For the three months ended March 31, 2012 and 2011, we recognized an impairment loss of $0.1 million and $0.2 million, respectively, related to the assets held for sale. In April 2012, the Company sold a compressor included in assets held for sale as of March 31, 2012, for $1.5 million and no gain or loss was recognized on that sale.

Recent Accounting Standards

In June 2011, the FASB issued ASU No. 2011-05, Presentation of Comprehensive Income. The issuance of ASU 2011-5 is intended to improve the comparability, consistency and transparency of financial reporting and to increase the prominence of items reported in other comprehensive income. The guidance in ASU 2011-5 supersedes the presentation options in ASC Topic 220 and facilitates convergence of U.S. generally accepted accounting principles and International Financial Reporting Standards by eliminating the option to present components of other comprehensive income as part of the statement of changes in shareholders' equity and requiring that all non-owner changes in shareholders' equity be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. The adoption of this guidance did not have a material impact on the Company’s consolidated financial statements.

In May 2011, the FASB issued ASU 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S GAAP and IFRS. This amendment of the FASB Accounting Standards Codification is to ensure that fair value has the same meaning in U.S. GAAP and IFRS and that their respective fair value measurement and disclosure requirements are the same. This guidance is effective during the interim and annual periods beginning after December 15, 2011. The adoption of the guidance did not have any material effect on the Company’s financial statements.